METHOD, SYSTEM, AND PRODUCTION AND STORAGE FACILITY FOR OFFSHORE LPG and LNG PROCESSING OF ASSOCIATED GASES

ABSTRACT

A method, system and production and storage facility is disclosed for offshore LPG and LNG processing of associated gases. The system includes a first production facility and a second production and storage facility. The first facility receives and processes produced fluids to produce crude oil, water and rich associated gases. The second facility includes a gas treatment unit for processing the rich associated gases to remove contaminants and produce a treated gas stream of hydrocarbons. The second facility also has at least one LPG and/or LNG production unit for producing one of LPG and/or LNG from the treated gas stream. At least one storage tank on the second facility stores at least one of the LPG and/or LNG. The second production facility may be a retrofit LNG or LPG carrier. The treatment unit, LPG and/or LNG production and needed offloading facilities and equipment can be added to the LNG/LPG carrier. Existing storage tanks can be modified as needed or else new storage tanks can also be added.

BACKGROUND

1. Technical Field

The present disclosure relates to offshore production facilitiesincluding floating production, storage and offloading (FPSO) vessels andfloating liquefied natural gas (FLNG) vessels that process producedfluids from undersea subterranean hydrocarbon-bearing reservoirs.

2. Description of Related Art

Produced fluids from hydrocarbon containing subterranean reservoirsoften contain mixtures of crude oil, water, entrained or associatedgases and other contaminants. Associated gas production streamsseparated from the remainder of the produced fluids must be processed toenable offshore crude oil production. Typically, the associated gasesinclude hydrocarbons containing one to five or more carbon atoms such asmethane (C₁), ethane (C₂), propane (C₃), butane (C₄) and heaviercondensates (C₅₊). The associated gases often contain other unwantedconstituents such as acid gases including carbon dioxide (CO₂) andhydrogen sulfide (H₂S), water and contaminants such as mercury (Hg).

It is desirable to extract hydrocarbon components from the associatedgas streams and produce liquefied petroleum gas (LPG), predominantly C₃and C₄ gases, and/or produce liquefied natural gas (LNG) (predominantlyC₁ and C₂ gases), as these saleable liquid products provide high marketvalue. The offshore LPG product extraction is typically performed oneither (1) an offshore fixed or floating oil and gas processingplatform, or (2) an oil FPSO (floating production, storage andoffloading) facility having additional gas processing facilities(oil/LPG FPSO). For both options, the valuable LPG products areoffloaded to a separate floating storage and offloading vessel (FSO), orrouted through a pipeline to shore. Currently, no LNG productionfacilities exist as part of an offshore processing platform or oil FPSO.Instead, lean residue gas is often reinjected into a subterraneanformation, or else is routed to a pipeline for gas sales or to shorewhere LNG production takes place.

In the offshore platform processing option, separate floating storagevessels, or separate export pipelines to shore, are required fortransport of the crude oil/condensate and LPG products. In the oil/LPGFPSO option, the combination of oil/gas production and LPG processingfacilities, along with the onboard oil/condensate/LPG storage, creates avery large and complex vessel. An example of a large oil/LPG FPSO vesselis a vessel operated by ConocoPhillips in the Belanak Field, SouthNatuna, Indonesia.

For both of the above offshore oil and gas processing options, theaddition of LPG production, LNG production and storage facilities addsconsiderably to complexity and cost. There is a need for an offshore oiland LPG processing alternative, which can be provided at a low cost.

A number of patents have suggested that natural gas be pretreated toremove undesirable contaminants on a first production vessel. Thesecontaminants include acid gases, water and components such as mercury.Subsequently, dedicated second floating LNG production vessels can beused to liquefy gases into LNG. Examples of such patents include U.S.Pat. Nos. 5,025,860, 6,003,603 and 6,889,522. In order to becommercially feasible, the first production vessels must be ofsufficient size to accommodate gas processing equipment needed to cleanup or treat hydrocarbon containing gases containing acid gases, waterand other contaminants, prior to treated gases being sent to the secondproduction vessel for liquefaction of natural gas to produce LNG.

SUMMARY

A production and storage facility, a method, and a system for offshoreLPG and/or LNG processing of associated gases is disclosed. The offshoreproduction and storage facility comprises a support structure thatsupports a gas treatment unit, at least one of an LPG and/or LNGproduction unit, and at least one storage tank for storing one LPG andLNG. The gas treatment unit is adapted to receive rich associated gasesand is capable of removing at least one of acid gases, water vapor andmercury from the rich associated gases to produce a treated gas stream.In one embodiment, the LPG production unit produces LPG. In anotherembodiment, both LNG and LPG are produced on the facility. One or bothof LPG and LNG may be stored on the facility. The facility may be aretrofit LNG or LPG carrier that has been converted to include the gastreatment unit and the LNG and/or LPG production units and any necessaryoffloading facilities or equipment.

The method provides for receiving a rich associated gas stream separatedfrom produced fluids containing hydrocarbons received from an offshoresubterranean reservoir. The rich associated gas stream is received on anoffshore production and storage facility and at least one of acid gases,water vapor and mercury are removed from the rich associated gases toproduce a stream of treated gas. At least one of liquefied petroleum gas(LPG) and liquefied natural gas (LNG) are produced from at least aportion of the treated gas. The LPG and/or LNG are then stored on theoffshore production and storage facility in one or more storage tanks.

The system is designed for separating produced fluids containinghydrocarbons received from an offshore subterranean reservoir. Thesystem includes a first offshore production facility and a secondoffshore production and storage facility and a conduit fluidlyconnecting the first and second facilities. The first offshoreproduction facility is adapted to receive produced fluids from at leastone subterranean reservoir and has facilities for separating theproduced fluids into crude oil, water and rich associated gases.

The second offshore production facility includes a gas treatment unit,at least one of an LPG and LNG production unit, and at least one LPG orLNG storage tank. The gas treatment unit is in fluid communication withthe conduit to receive the rich associated gases from the firstproduction facility and is capable of removing at least one of acidgases, water vapor and mercury from the rich associated gases to producea treated gas stream. At least one of an LPG and LNG production unit iscapable of producing LPG and/or LNG from at least a portion of thetreated gas stream. LPG and/or LNG produced may be stored on the secondoffshore production facility.

The second production and storage facility may be an LPG carrier or anLNG carrier which has been retrofit to include a gas treatment unit forremoving at least one of acid gases, water vapor and mercury from therich associated gases and which includes at least one of an LPG and anLNG production unit to produce one of LPG and LNG. Existing storagetanks can be retrofit to store LNG and/or LPG as needed. Existing ornewly added offloading facilities and equipment may be used to offloadthe LPG and/or LNG.

BRIEF DESCRIPTION OF THE DRAWINGS

These and other objects, features and advantages of the embodimentsdisclosed will become better understood with regard to the followingdescription, pending claims and accompanying drawings where:

FIG. 1 is a schematic drawing of a system wherein hydrocarbon containingfluids are produced from one or more subsea reservoirs with the producedfluids being separated into crude oil, water and rich associated gaseson a first production facility, and compressed rich associated gasesbeing sent to and processed on a cooperating second production andstorage facility to remove contaminants in the rich associated gases toproduce a treated gas stream which yields LPG and/or LNG;

FIG. 2 is a block diagram of the first production facility thatcooperates with the adjacent second production and storage facility toproduce LPG for offloading to a LPG carrier. In addition, this secondproduction and storage facility produces C₅₊ liquid condensate that isreturned to the first production facility for blending with crude oil,and residue gas which is also returned to the first production facility;

FIG. 3 is a schematic diagram of a portion of the second production andstorage facility of FIG. 2 used to treat the rich associated gases toremove acid gases, water and other contaminants and then the treatedgases are further processed into residue gas, LPG, and C₅₊ liquidcondensates;

FIG. 4 is a block diagram of another embodiment of a first productionfacility that produces rich associated gases from produced fluids andsends the rich associated gases to a second production and storagefacility for treatment or removal of contaminants to produce a treatedgas stream which is processed into LNG, LPG, and C₅₊ liquid condensate;and

FIG. 5 is a schematic diagram of an LNG production unit used on thesecond production and storage facility of FIG. 4 to produce LNG,predominantly C₂₊ liquids and residue gas from treated associated gases;the C₂₊ liquids are then converted to LPG and C₅₊ liquid condensates.

DETAILED DESCRIPTION OF THE EXEMPLARY EMBODIMENTS

For the purposes of this disclosure, the following terms shall havefollowing meanings:

Condensate refers to liquids recovered from rich associated gases havingpredominantly C₅₊ hydrocarbons;

LNG (Liquefied natural gas) refers to a cryogenic fluid comprisingpredominately methane (C₁) with lesser amounts of C₂₊ hydrocarbons,which is sufficiently cold to remain in a liquid state at or nearatmospheric pressures;

LPG (Liquefied petroleum gas) refers to fluids comprising predominatelyC₃ and C₄ hydrocarbons, which can either be refrigerated to remainliquid at near atmospheric pressures or pressurized to remain liquid atatmospheric temperature;

Residue gas refers to gases recovered from LPG or LNG processing thatcontain primarily C₁ and C₂ hydrocarbons;

Rich associated gases refers to gases separated from hydrocarboncontaining produced fluids on a first production facility, includingcrude oil and water, which contain contaminants, such as acid gases,water vapor and mercury, and gaseous hydrocarbons including C₁, C₂, C₃,C₄ and C₅₊ components;

Lean gases refers to gases containing primarily C₁ and C₂ from whichheavier hydrocarbon components C₃₊ have been substantially removed.

Illustrative embodiments are described below. In the interest ofclarity, not all features of an actual embodiment are described in thisspecification. It will of course be appreciated that in the developmentof any such actual embodiment, numerous implementation-specificdecisions must be made to achieve the developers' specific goals, suchas compliance with system-related and business-related constraints,which will vary from one implementation to another. Moreover, it will beappreciated that such a development effort might be complex andtime-consuming, but would nevertheless be a routine undertaking forthose of ordinary skill in the art having the benefit of thisdisclosure.

Offshore Production Facility Producing Crude Oil and Rich AssociatedGases

FIG. 1 shows an exemplary embodiment of a system 20 wherein first andsecond cooperating offshore production facilities 22 and 24 are used toprocess produced fluids from one or more subterranean reservoirs, intomarketable products including crude oil, liquefied petroleum gas (LPG)and/or liquefied natural gas (LNG), and possibly lean residue sales gas.First production facility 22 receives produced fluids from one or moresubterranean reservoirs 26 a, 26 b and 26 c by way of a subsea flowlines 30 a, 30 b, 30 c that are fluidly connected to a manifold 32.Manifold 32 is connected to a flow line 34 that leads to a riser 36 thatconnects to first production facility 22. Tether lines 40 moor firstproduction facility 22, which in this embodiment, is a floatingproduction, storage and offloading FPSO vessel. By way of example andnot limitation, first production facility 22 could also be a fixed orfloating platform, a jacketed platform or a semi-submersible platform.

Sales export line or pipeline 42 leads to a sales facility 44 thatreceives processed fluids from first or second production and storagefacility 22 or 24. Import line 46 is used to import rich associated gasto second facility 24 from first production facility 22. Residue gasline 48 and condensate line 50 bring residue gas and liquid condensate,respectively, from second production and storage facility 24 back tofirst production facility 22.

The produced fluids 26 are separated into crude oil, water and gasesusing separation and compression facilities 52 on first productionfacility 22. These gases 70 are referred to as “associated gases” andare sent on to second production and storage facility 24 for further gastreatment and separation into hydrocarbon products having differingcarbon chain lengths.

In this particular exemplary embodiment, separation facility 52separates the gases and liquids using a primary multi-stage separatortrain 54 which includes a three-phase separator (oil/water/gas) followedby a secondary oil/gas separator. Liquids are sent to an optionalwater-crude oil separator 60 where water is separated from crude oil.Secondary water separation from crude oil may be carried out using awater treatment apparatus 62 for gravity separation or may include acentrifuge. The water is sufficiently treated such that it meetsenvironmental standards appropriate for disposal of the treated wateroverboard into the sea. Those skilled in the art of water treatment willappreciate other combinations of equipment can also be used to treat theproduced fluids to produce water ready for disposal.

The associated gases 70 are separated from the crude oil and water bypassing the produced fluids through the series of separators comprisingseparator train 54 that operate at decreasing pressures allowingentrained gases to escape from the crude oil and/or water. Theseassociated gases are then typically compressed in a gas compressionfacility 58 from the various separators, to a common higher pressuresuitable for gas export or gas reinjection. Ideally, the crude oil hasenough gases removed such that only small amounts of hydrocarbon gasesare left in the crude oil to dissipate at atmospheric pressure. Suchcrude oil is referred to as “stabilized oil.” Techniques for producingstabilized crude oil at an oil production facility are well known.

The stabilized crude oil is stored in one or more crude oil storagetanks 64 located on first production facility 22. The stabilized crudeoil preferably has a vapor pressure of less than 14.7 psia (101 kPa),and even more preferably less than 5 psia (34 kPa). See U.S. Pat. No.6,541,524 for more details on crude vapor pressure regulations for crudeoil tankers. A crude oil tanker 68 may be used to transport the crudeoil to a distant location for refining operations. A conventional crudeoil transport conduit 69 may be used to convey the crude oil from firstproduction facility 22 to tanker 68.

LPG Production and Storage Facility

Referring now to FIG. 2, a stream of rich associated gases 70 istransferred by import line 46 to second production and storage facility24 with an arrival pressure in the range 1000-1200 psig (6900−8300 kPa).In one embodiment, as shown in FIG. 2, the stream of feed or richassociated gases 70 is processed to produce liquefied petroleum gas(LPG) 74 comprising predominantly C₃ and C₄ components (propane andbutane), a residue gas 72 comprising primarily C₁ and C₂ gases, and astream of C₅₊ liquid condensate 76. It is further envisioned that thepropane and butane could further be separated from one another andstored in separate propane and butane storage tanks on second productionand storage facility 24 if so desired.

Rich associated gases 70 are first pretreated using a gas treatment unit80 to remove, by way of example and not limitation, one or more ofcontaminants such as acid gases (CO₂, H₂S), water vapor and othercontaminants such as mercury (Hg). Contaminants should be sufficientlyremoved from the stream 70 of rich associated gases to produce a treatedgas stream 82 that can be readily processed into LPG and/or LNG. Beloware exemplary, and not limiting, levels below which the stream 70 ofrich associated gases may be treated to produce treated gas stream 82 ofsuitable specification:

TABLE 1 Level of Contaminants in Treated Gas Stream Contaminant Maximumamount of Contaminant Component Component in Treated Gas Stream Carbondioxide (CO₂) <50 parts per million by volume; Hydrogen Sulfide (H₂S) <3parts per million by weight; Water vapor (H₂0) <1 part per million byweight; Mercury (Hg) <0.1 micrograms/square meter³

In the embodiment shown in FIG. 2, at least a portion of the residue gas72 can be combusted to produce heat and energy for machinery andutilities on second production and storage facility 24. The residue gas72 can also be sent by return line 48 back to the first productionfacility 22 for recompression and sales gas export or reinjection into asubterranean reservoir. Also, a portion of the residue gas 72 can becombusted on first production facility 22. Extra compression units (notshown) may be added to second production facility 24 as needed forrecompression and gas export or reinjection of the residue gas 72.

LPG 74 produced in LPG production unit 84 is routed to one or more LPGstorage tanks 94 located on second production and storage facility 24.Periodically, LPG 74 is removed from the one or more LPG storage tanks94 using conventional LPG transfer equipment 100 and offloaded to a LPGcarrier 104 for transport to a market destination for LPG 74.

Referring now to FIG. 3, additional details are shown for thepretreatment and separation of the rich associated or feed gases 70.Feed or associated gas 70 is received by gas treatment unit 80. Acidgases such as carbon dioxide (CO₂) and/or hydrogen sulfide (H₂S) areremoved from rich associated gases 70. By way of example and notlimitation, another acid gas that might be removed includes carbonylsulfide (COS). For removal of carbon dioxide, a conventional aminesolvent-based system 110 may be used to strip CO₂ and H₂S from richassociated gas stream 70. As another non-limiting example, a mole sievebased acid gas removal system may be used. A prime consideration for allof the equipment selected to be used on second production and storagefacility 24 is that that the equipment be compact and lightweight.

Water vapor entrained in the gas stream may be removed such as by usingmole sieve dehydrator 114 to prevent freezing of water vapor in acryogenic section of LPG production unit 84. The gas stripped of theacid gases and dehydrated is then routed to a mercury removal system118.

The stream 82 of treated gas is pre-cooled by passing through a feedgas/residue gas heat exchanger 122. Feed gas heat exchanger 122, in thisexemplary embodiment, is a brazed aluminum plate fin type, with treatedgas 82 flowing through a coil section 124, and a cold residue gaspassing through a coil section 126, and condensed liquids passingthrough a coil section 128. The precooled stream 82 of treated gas isrouted through conduit 130 to a cold separator 140 for separation of apredominant C₁ expanded cold vapor stream and a C₂₊ natural gas liquidstream. The cold vapor stream flows through conduit 142 to aturboexpander unit 132, which yields an expanded cryogenic stream thatflows through conduit 134 to the top section of a deethanizer column144. The stream of liquids C₂₊ from the cold separator 140 is throttledthrough a pressure let down valve 135, and flows through coil section128 of the feed gas heat exchanger 122, and through a conduit 136 intothe lower section of the deethanizer column 144. Deethanizer column 144yields a predominantly C₁, C₂ overhead cold residue gas stream thatpasses through gas conduit 146 to heat exchanger 122, and emerges aslean residue gas 72 which is exported through conduit 48 from secondproduction and storage facility 24, net fuel gas needs used forcombustion on second production and storage facility 24.

Deethanizer column 144 yields a bottoms stream of heavier components C₃₊that are routed through a liquid conduit 150 to a depropanizer column152 in which the LPG (C₃, C₄) fluids 74 are separated from the heavierstream 76 of C₅₊ liquid condensate. The deethanizer column 144 typicallyhas an internal condenser and thermosyphon reboiler (not shown). Thedepropanizer column 152 has (not shown) an air-cooled overheadcondenser, reflux drum, reflux pumps, and thermosyphon reboiler.

The LPG 74 (C₃, C₄) is then transferred to and stored in one or more LPGtanks 94 adapted to store LPG. By way of non-limiting examples, theseLPG storage tanks may be of the Moss spherical type tank, orself-supporting independent prismatic (SPB) type A or type B tank. TheC₅₊ condensate 76 is sent through condensate export line 50 to be mixedand stored with the crude oil in crude oil storage tank 64 on the firstproduction facility 22. As referenced above, the mixture of C₅₊condensate 76 and crude oil should meet industry specificationsnecessary for transport of crude oil on crude oil tankers. As analternative, the C₅₊ condensate 76 may be used for combustion on secondproduction and storage facility 24 by boilers or other operationalequipment. If all of C₅₊ condensate is consumed on facility 24, then noexport line 50 is necessary.

Floating LPG Production and Storage Facility

In one exemplary embodiment, second production and storage facility 24may be a floating LPG (FLPG) developed at relatively low cost, byconversion of an existing LNG carrier vessel (such as with Moss-typestorage tanks), that is still within its design service life. The FLPGproduction facility could also be developed at relatively low cost, byconversion of an existing LNG or LPG carrier vessel (such as with IHIself-supporting prismatic type B (SPB)-type storage tanks), that is alsostill within its design service life. By way of example and notlimitation, the FLPG production vessel might process a rich associatedgas stream 70 with a flow rate in the range of 50-150 MMSCFD (1.4-4.2million cubic meters per day at 15.6° C.). As another non-limitingexample, production facility 24 might process a rich associated gasstream with natural gas liquids (C₂₊) content in the range 5-20% (mol.).

Deethanizer and depropanizer reboilers (not shown) can be steam-drivento utilize the existing steam system on an LNG or LPG carrier. Theexisting steam system may need to be upgraded for the new implementationof producing LPG liquids and liquid condensates. LPG storage tanks andtandem LPG offloading facilities on an existing LPG carrier can bereused for the FLPG production facility. LNG storage tanks on anexisting LNG carrier can be recertified for LPG service, and tandem LPGoffloading facilities added to the existing LNG carrier vessel, for theconverted FLPG production facility. Temporary storage tanks can also beadded to an existing LNG or LPG carrier for storing residual C₅₊ liquidcondensate which can be later combusted or transferred to a crude oiltanker.

Electrical power generation equipment on an existing LPG or LNG carriercan be reused for the FLPG production facility, with additionalelectrical power requirements to be provided by a new aeroderivativeturbogenerator. Utility systems on an existing LPG or LNG carrier (e.g.,instrument, air, nitrogen, fuel gas, firewater, etc.), and control andsafety systems can be reused and upgraded if needed, for the FLPGproduction facility. The existing LPG or LNG carrier can be retrofittedwith a turret mooring system, designed for station keeping of the FLPGproduction facility. The turret would have sufficient riser capacity forthe associated gas import line and lean residue gas and residual C₅₊liquid condensate export lines 48, 50.

LNG/LPG Production and Storage Facility

FIG. 4 shows an exemplary second embodiment of a system 200 including afirst production vessel 202 and a second production vessel 204. Firstproduction vessel 202 again may be an offshore fixed or floating oil andgas processing platform, or an oil FPSO vessel where rich associatedgases 206 are produced and then exported to second production vessel 204with an arrival pressure in the range 1000-1200 psig. Associated gases206 are treated to remove contaminants and converted into liquefiednatural gas (LNG) 210, liquefied petroleum gas (LPG) 212 and liquid C₅₊condensate 214. A stream of residue gas 216 is also produced.

Associated gases 206 are delivered from first production facility 202using an import line 222 to a gas treatment unit 224 on secondproduction vessel 204 at an arrival pressure in the range 1000-1200 psig(6900-8300 kPa). Associated gases 206 are treated to remove one or moreof the components of acid gases (CO₂, H₂S), water vapor, andcontaminants such as Hg, to produce a treated hydrocarbon gas stream 226(see FIG. 5) that is delivered by a gas conduit 230 to a liquefiednatural gas (LNG) production unit 232.

LNG production unit 232 produces LNG 210 along with a predominantly C₂₊stream of liquids and lean residue gas 216. LNG production unit 232 andits operation will be described in greater detail below with referenceto FIG. 5. Produced LNG 210 is first conveyed by a cryogenic conduit 234to one or more cryogenic LNG storage tanks 236. By way of example, andnot limitation, these LNG storage tanks may be of the Moss sphericaltype tank, or self-supporting independent prismatic (SPB) type B tank.After sufficient LNG 210 is produced to fill the LNG storage tanks, LNG210 is transferred through a cryogenic conduit 240 and specialized LNGtransfer equipment 242 by way of a conduit 244 to an LNG carrier 246,which transports the LNG 210 to distant markets. By way of example andnot limitation, such specialized LNG transfer equipment 242 may includeequipment such as is described in U.S. Pat. Nos. 7,726,358 and7,726,359.

A liquefied petroleum gas (LPG) production unit 250 receives C₂₊ liquidsfrom LNG production unit 232 by way of liquids conduit 252. LPGproduction unit 250 separates C₂, C₃, C₄ liquids from heavier liquids toproduce LPG 212 and C₅₊ condensate 214. Equipment similar to thatdescribed above with respect to FIG. 3, i.e., deethanizer column 144,and depropanizer column 152, may be used by LPG production facility 250to separate C₂₊ liquids into LPG 212 and C₅₊ condensate liquids 214.

LPG 212 produced by LPG production unit 250 is conveyed by a liquidsconduit 256 to one or more LPG storage tanks 260. When sufficient LPG212 has been accumulated, LPG 212 is conveyed by a liquid conduit 262 toLPG transfer equipment 264, and liquids conduit 266 to a LPG transportvessel 268. LPG 212 can then be transported by LPG transport vessel 268to market locations.

As most of the lighter C₁, C₂ gases are converted into LNG 210 by LNGproduction unit 232, a return or export line for residue gas 216 is notabsolutely required. Whatever residue gas 216 is produced may becombusted on second production and storage facility vessel 204 byboilers or other operational equipment. Also, boil-off gas (BOG) fromthe production, storage and transfer of LNG 210 may also be collectedand combusted (not shown). Alternatively, the residue gas 216 and/or BOGmay also be recompressed, and mixed with treated gas stream 230 from gastreatment unit 224 and reprocessed by LNG production unit 232.

Liquid C₅₊ condensate 214 will be returned to first production vessel202 to be mixed with crude oil and stored in one or more crude oilstorage tanks 220. The mixture of crude oil and condensate can then beoffloaded to a crude oil tanker (not shown) for transport to an onshorerefinery.

FIG. 5 shows a more detailed embodiment of the exemplary LNG productionunit 232 as described above with reference to FIG. 4. This LNGproduction unit utilizes a nitrogen expander loop refrigeration process,which can also be configured as a compander unit. The LNG productionunit 232 should be compact in size and lightweight, as deck space on,and weight capacity of, an offshore structure is generally at a premium.

Treated gas 226 is introduced into LNG production unit 232. First, aturboexpander 240 may be used to expand and precool treated gas inconduit 228 prior being input into a cold box 280. Cold box 280 has a“warm” section 282 and “cold” section 284. In this particularembodiment, nitrogen expander loop equipment 286 is used forrefrigeration, which is detailed as follows. Relatively warm nitrogen isdelivered by a coil section 292 to a first stage compressor 294 wherenitrogen is compressed to a predetermined interstage pressure anddelivered to coil section 296. A cooler 300 is used for nitrogencompression intercooling, which utilizes sea water as the cooling media.Nitrogen is compressed by a second stage compressor 302 to apredetermined final discharge pressure and sent to another coil section304. The further compressed nitrogen is again cooled by a secondaftercooler 306. Additional compression stages can be added ifnecessary. An electric motor 290 is used to drive both the first stagecompressor 294 and second stage compressor 302.

High-pressure nitrogen is routed by a coil section 308 into the warmsection of the cold box 282 for pre-cooling. The pre-cooled nitrogen incoil section 308 is delivered to and rapidly expanded in turboexpander310 to cool the nitrogen to a low temperature, i.e., such as below −270°F. (−170° C.). The low pressure cold nitrogen is then routed to coldsection 284 of the cold box 280 to provide liquefaction duty for anatural gas separator gas stream 322 (described below). After the lowpressure cold nitrogen has been warmed by cooling the lean gas stream322, the nitrogen flows to the warm section of the cold box 280, toprovide cooling duty for expanded feed gas stream 228 and precooled highpressure nitrogen loop stream in coil section 308. The nitrogen thenexits from cold box 280 and returns to coil section 292 to be recycledand recompressed again by first stage compressor 294.

Expanded treated gas stream 228 is further cooled in warm section 282 ofthe cold box 280 and is delivered to natural gas separator 320 thatseparates this stream into predominantly C₁, C₂ lean gases carried bygas conduit 322 and a bottom liquid stream of predominantly C₂₊.Extracted C₂₊ liquids are passed out of LNG production unit 232 to beprocessed by LPG production unit 250, as described above with referenceto FIG. 4.

The lean gas stream in conduit 322 is passed back into cold section 284of the cold box 280 in preparation for liquefaction. Upon exiting coldbox 280, the liquefied lean gas stream is passed through an expansionvalve 324 to reduce the pressure for LNG production and storage, andthen routed to a cold separator 326. LNG 210 is passed from the bottomof cold separator 326 and flows from LNG production unit 232 by conduit234 to LNG storage tanks 236 for storage. An overhead stream of residuegas 216 is delivered from cold separator 326 and out of LNG productionunit 232. One or more portions of residue gas 216 can then be combustedby equipment on second production vessel 204, or recompressed andreturned to LNG production unit 232 for reprocessing.

The liquefaction process is designed to produce a rich LNG (to a maximumgross heating value GHV specification). The pre-cooling section of theliquefaction process is used to extract sufficient NGL components (C₂₊)from the treated stream 226 to the extent needed to meet the LNG maximumGHV specification.

The extracted C₂₊, stream is sent to LPG production unit 250 and flowsinto the top section of a deethanizer column to yield a predominantlyC₁, C₂ overhead residue gas stream that is mixed with residue gas 216,and a bottoms C₃₊ stream that is sent to a depropanizer column which isused to separate a C₃/C₄ LPG product 210 in the overhead stream, from abottoms residual C₅₊ condensate stream, in a similar manner to thatdescribed above with respect to the first embodiment shown in FIGS. 2and 3. The overhead condensed liquid C₃/C₄ LPG product 210 is routed tothe LPG storage tanks 260. The depropanizer column (not shown) mayinclude an air-cooled overhead condenser, reflux drum, reflux pumps, andthermosyphon reboiler.

Floating LNG/LPG Production Facility

A floating LNG/LPG production facility (FLNG) could also be developed atrelatively low cost, again ideally by conversion of an existing LNG orLPG carrier vessel. The LNG and LPG products would share the existingLNG or LPG carrier vessel storage. Use of the pre-existing storageoffers a potential cost advantage compared to an integrated offshoreoil/gas/LPG processing facility, coupled with pipeline transport andstorage of LNG and/or LPG products onshore, or floating storage vessels.

The floating LNG/LPG (FLNG) production vessel can be developed atrelatively low cost, by conversion of an existing LNG carrier vessel(with Moss-type storage tanks), that is still within its design servicelife. The FLNG production vessel could also be developed at relativelylow cost as well, by conversion of an existing LNG or LPG carrier vessel(with IHI SPB-type storage tanks), that is still within its designservice life. The FLNG production facility would take a rich associatedgas stream from an offshore fixed or floating oil and gas processingplatform, or an oil FPSO, and process this rich associated gas forproduction of a rich LNG, and a mixed C₃/C₄ LPG product, which aresaleable products of high market value. A residual C₅₊ condensateproduct could be routed back to oil and gas processing platform, or oilFPSO. As an alternative, the C₃ and C₄ products can be separated andstored in separate propane and butane storage tanks if so desired.

The FLNG production facility would include a gas treatment unit, an LNGproduction and LPG production units, which would be retrofitted into theexisting LNG or LPG carrier vessel. The associated or feed gas is routedto an acid gas removal unit (amine solvent-based) for removal of CO₂(and traces of H₂S, if present), and to mole sieve dehydrators forremoval of water vapor, sufficient to avoid freezing in the cryogenicsection of the LNG production unit. The gas is then routed to a mercuryremoval system.

The treated gas stream is routed to a liquefaction unit for productionof the LNG stream. It is envisioned that this may be a nitrogen expanderloop type liquefaction process with cold box for compactness of systemdesign. The liquefaction process will be designed to produce a rich LNG.The pre-cooling section of the liquefaction process will be used toextract NGL components (primarily C₂₊) from the treated gas stream, tothe extent needed to meet the rich LNG maximum GHV specification, TheLNG is then routed to a cold separator, and then to at least one LNGstorage tank.

The C₂₊, stream is sent to a deethanizer column to yield an overheadresidue gas stream that is mixed with cold separator vapor, and will beused for FLNG fuel gas. The bottoms C₃₊ stream is sent to a depropanizercolumn, which would separate a C₃/C₄ LPG product in the overhead stream,from a bottoms residual C₅₊ condensate stream. The mixed C₃/C₄ LPGproduct is routed to the LPG storage tanks The depropanizer column mayinclude an air-cooled overhead condenser, reflux drum, reflux pumps, anda thermosyphon reboiler. The deethanizer and depropanizer reboilerswould be steam-driven to utilize the existing steam system on the LNG orLPG carrier. The existing steam system may need to be upgraded for thenew service. As an alternative, it is also possible that a separation ofthe C₂₊ components may be done in a single taller column with a leanresidue gas stream, an LPG (C₃/C₄) side stream and a C₅₊ bottoms stream.

LNG storage tanks and side-by-side LNG offloading facilities on anexisting LNG carrier would be reused for LNG service on the FLNG vesselproduction facility, and upgraded if needed. LPG storage tanks on anexisting LPG carrier would be recertified for LNG service, andside-by-side LNG offloading facilities would be added to the LPG carriervessel, for LNG service on the FLNG vessel production facility.

LNG storage tanks on an existing LNG carrier would be recertified forLPG service, and tandem LPG offloading facilities would be added to theLNG carrier vessel, for LPG service on the FLNG vessel productionfacility. LPG storage tanks and tandem LPG offloading facilities on anexisting LPG carrier would be reused for LPG service on the FLNG vesselproduction facility.

Temporary storage tanks can be added to an existing LNG or LPG carrierfor the C₅₊ condensate product. Electrical power generation equipment onan existing LPG or LNG carrier could be reused for the FLNG productionfacility, with additional electrical power requirements to be providedby a new aeroderivative turbogenerator. Utility systems on an existingLPG or LNG carrier (e.g., instrument air, nitrogen, fuel gas, firewater,etc.), and control and safety systems could be reused and upgraded ifneeded, for the new FLNG production facility service.

The existing LPG or LNG carrier can be retrofitted with a turret mooringsystem, designed for station keeping of the FLNG vessel, and to havesufficient riser capacity for the associated gas import, and residualC₅₊ condensate export lines.

While in the foregoing specification this invention has been describedin relation to certain preferred embodiments thereof, and many detailshave been set forth for purpose of illustration, it will be apparent tothose skilled in the art that the invention is susceptible to alterationand that certain other details described herein can vary considerablywithout departing from the basic principles of the invention.

For example, it is envisioned that second production and storagefacilities 24, 204 can be utilized with an existing production facilitythat either flares gas, exports the gas onshore or reinjects the gasinto subterranean formations. In this manner, valuable products such asLPG and LNG can be captured that might otherwise not be lost.

What is claimed is:
 1. A method for separating produced fluidscontaining hydrocarbons received from an offshore subterraneanreservoir, the method comprising: (a) receiving a rich associated gasstream on an offshore production and storage facility and removing atleast one of acid gases, water vapor and mercury from the richassociated gases to produce a treated gas; (b) producing at least one ofliquefied petroleum gas (LPG) and liquefied natural gas (LNG) from atleast a portion of the treated gas; and (c) storing the at least one ofLPG and LNG in at least one of a liquefied petroleum gas (LPG) storagetank and a liquefied natural gas (LNG) storage tank on the productionand storage facility.
 2. The method of claim 1 wherein: LPG is producedin step (b); and LPG is stored in step (c) in at least one LPG storagetank located on the production and storage facility.
 3. The method ofclaim 1 wherein: LNG is produced in step (b); and LNG is stored in step(c) in at least one LNG storage tank located on the production andstorage facility.
 4. The method of claim 1 wherein: LPG and LNG are bothproduced on the production and storage facility in step (b).
 5. Themethod of claim 4 wherein: LNG is stored in at least one LNG storagetank and LPG is stored in at least one LPG storage tank.
 6. The methodof claim 1 wherein: acid gases are removed from the rich associatedgases in step (a).
 7. The method of claim 1 wherein: the production andstorage facility is one of an LPG carrier or an LNG carrier which isretrofit to include a gas treatment unit for removing at least one ofacid gases, water vapor and mercury from the rich associated gases andwhich includes at least one of an LPG and LNG production unit to produceone of LPG and LNG.
 8. An offshore production and storage facilitycomprising: a support structure; a gas treatment unit which is adaptedto receive rich associated gases, the gas treatment unit mounted on thesupport structure and being capable of removing at least one of acidgases, water vapor and mercury from associated gases to produce atreated gas stream; at least one of an LPG production unit and an LNGproduction unit mounting on the support structure and being capable ofproducing at least one of LPG and LNG from at least a portion of thetreated gas stream; and at least one storage tank on the supportstructure to store at least one of the LPG and LNG.
 9. The offshoreproduction and storage facility of claim 8 wherein: the at least one ofan LPG production unit and an LNG production unit is a LPG productionunit; and the at least one storage tank includes at least on one storagetank for storing LPG.
 10. The offshore production and storage facilityof claim 9 wherein: the at least one of an LPG production unit and LNGproduction unit is an LNG production unit; and the at least one storagetank includes at least on one storage tank for storing LNG.
 11. Theoffshore production and storage facility of claim 9 wherein: the atleast one of an LPG production unit and LNG production unit includesboth an LPG production unit and an LNG production unit.
 12. The offshoreproduction and storage facility of claim 11 wherein: at least onestorage tank includes at least on one storage tank for storing LNG andat least one storage tank for storing LPG.
 13. The offshore productionand storage facility of claim 9 wherein: the supporting structure is afloating vessel.
 14. The offshore production and storage facility ofclaim 13 wherein: the floating vessel is one of a retrofit LNG carrierand a retrofit LPG carrier.
 15. A system for separating produced fluidscontaining hydrocarbons received from an offshore subterraneanreservoir, the system comprising: a first offshore production facilityand a second offshore production and storage facility and a firstconduit fluidly connecting the first and second facilities; the firstoffshore production facility being adapted to receive produced fluidsfrom at least one subterranean reservoir and having facilities forseparating the produced fluids into crude oil, water and rich associatedgases; the second offshore production facility including: a gastreatment unit in fluid communication with the first conduit to receivethe rich associated gases from the first production facility and capableof removing at least one of acid gases, water vapor and mercury from therich associated gases to produce a treated gas stream; at least one anLPG production unit capable of producing LPG from a portion of thetreated gas stream and one of an LNG production unit capable ofproducing LNG from a portion of the treated gas stream; and at least onestorage tank for storing at least one of LPG or LNG on the secondproduction and storage facility.
 16. The system of claim 15 wherein: theone an LPG production unit capable of producing LPG from a portion ofthe treated gas stream and one of an LNG production unit capable ofproducing LNG from a portion of the treated gas stream includes an LPGproduction unit.
 17. The system of claim 15 wherein: the one an LPGproduction unit capable of producing LPG from a portion of the treatedgas stream and one of an LNG production unit capable of producing LNGfrom a portion of the treated gas stream includes an LNG productionunit.
 18. The system of claim 15 wherein: the at least one an LPGproduction unit capable of producing LPG from a portion of the treatedgas stream and an LNG production unit capable of producing LNG from aportion of the treat gas stream includes both an LPG production unit andan LNG production unit.
 19. The system of claim 18 wherein: the at onestorage tank for storing at least one of LPG or LNG includes at leastone storage tank for storing LPG and at least one storage tank forstoring LNG located on the second production and storage facility.